Say “midstream expansion” to most energy-industry people and visions of the Dakota prairie or the wooded Alleghenies come to mind. But out there beyond the beach, far into the Gulf of Mexico, some of the largest and most ambitious midstream projects around are taking shape—with capex budgets in the hundreds of millions.

Given the exploratory scale and risk involved, the Gulf ’s Outer Continental Shelf (OCS) draws only the majors and very large independents. Likewise, the midstream component includes big-name operators in the industry. The federal government defines the deep Gulf as water depths of 200 meters (656 feet) or more.

The deepwater Gulf right now is a crude oil play. Natural gas isn’t a target given current prices. But industry sources point out much of the associated gas produced with that crude is very wet with high natural gas liquids (NGL) content. That creates midstream opportunities in addition to upstream producers’ desire to do what they do best, drill and produce, and turn over the gathering, processing and transportation functions to someone else.

Science fiction

Developing deepwater reserves is frontier stuff made possible only because of technological innovation, Claudi Santiago, chief operating officer of First Reserve, a private equity firm, tells Hart Energy—one of the “megatrends” he sees currently in the energy business. “Five years ago, it was unthinkable that we would be able to monetize and exploit oil from deep water,” Santiago says.

Leading-edge seismic techniques found the plays, then advanced drill ships and production platforms that look like something out of a science fiction movie have made the OCS pay. These plays are huge and no fiction.

Take as one example BP’s Thunder Horse semisubmersible platform, which has a production capacity of 250,000 barrels (bbl.) per day of oil and 200 million cubic feet (MMcf) per day of gas. BP-operated pipelines, including the Proteus and Endymion crude lines, and Okeanos and Destin gas systems, move production to shore.

BP estimates recoverable reserves at 1 billion bbl. of oil equivalent from the play’s twin, north and south, fields. Numbers like that get producers’ attention regardless of where the reserves lie, even if the water is 6,000 feet deep, as it is at Thunder Horse. ExxonMobil is its partner.

There are a lot more reserves out there to keep drillers busy. The U.S. Bureau of Offshore Energy Management (BOEM), formerly known as the Minerals Management Service, estimates the western planning area of the Gulf has 12 billion bbl. of oil and 69.5 trillion cubic feet (Tcf) of gas that is technically recoverable. The BOEM’s central area looks even better with estimates of 30.9 billion bbl. and 133.9 Tcf, respectively.

Growing again

Activity has picked up after the April 2010 Macondo blowout and the subsequent government halt to most Gulf drilling.

Given the U.S. Gulf ’s comparatively stable business and political structure, existing infrastructure, mostly agreeable weather (except for occasional hurricanes) and those big potential reserves, it’s understandable why numerous foreign firms have joined a host of domestic upstream firms in the deepwater hunt.

The U.S. Energy Information Administration (EIA) forecasts Gulf production to average around 1.4 million bbl. of oil per day equivalent this year—about one-fifth of total domestic production. That’s down from a December 2009 peak of 1.7 million bbl. per day shortly before the Macondo blowout. But production numbers continue to climb. EIA forecasts Gulf production will tick up to 1.5 million bbl. daily by 2015. And as development continues and infrastructure develops, more and more producers look to lay off midstream operations to partners.

That represents one, big potential midstream market, points out Rory Miller, senior vice president of the Atlantic-Gulf operating area for Williams Partners LP.

“Once the business gets sorted out and it becomes commonly understood how to best attack a problem, then the majors tend to have better things to let their scientists work on, and they start outsourcing to other players,” Miller tells Midstream Business. “That certainly happened onshore and it’s happening in a big way offshore now as well. There is a very robust and growing [Gulf] midstream business in terms of building oil and gas pipelines.”

Williams is emerging as a key offshore midstream player. It’s laying the new Keathley Canyon Connector to move associated gas produced from new, deepwater plays offshore Louisiana. Capacity will be 400 MMcf per day with service scheduled to start in mid-2014.

It will join Williams’ existing Discovery Pipeline that feeds the firm’s 600 MMcf per-day Larose gas processing plant, south of New Orleans. The new system will serve Exxon- Mobil’s Hadrian North and Hadrian South fields, as well as other upstream players developing in the area. Williams owns 60% of the Discovery system and serves as operator. DCP Midstream Partners LP owns the other 40%.

Economics lesson

Midstream economics change offshore, Miller explains.

“Ten years ago, I would tell you that it was more expensive to lay pipeline in the deepwater Gulf of Mexico. Interestingly enough, today that’s not true. In many areasonshore, the cost-per-mile is higher onshore than it is offshore,” he says, due to the growing amount of required environmental work and permitting for landside projects.

But that’s not the case with offshore processing. Space on offshore platforms comes at a price—a premium that makes even clearing land and bulldozing a site in the most rugged corners of the Appalachians seem cheap. Those critical factors—space and weight—define every offshore platform project. They are even more crucial as OCS water depths require the use of floating facilities, such as semisubmersibles and tension-leg platforms.

“In the deep water, you’re in depths where putting in a fixed-leg structure is no longer an option. So you have floating real estate, so to speak,” he says. “Then you also have to worry about your load-carrying capacities. You need enough buoyancy to hold up whatever load you’ve got and you need enough square footage to put whatever equipment you need out there on it. So the latent space is really expensive offshore.”

The federal government classifies all pipeline operations in the deeper Gulf as unregulated gathering, rather than gas transmission, which offers a plus to regulatory questions offshore for midstream operators. Williams has work under way on its new Gulfstar I sparbased floating production system at Gulf Coast shipyards. Hull fabrication is being done at Ingleside, Texas, with the topsides coming together at Houma, Louisiana.

Tubular Bells

The floating platform will be tethered to the seafloor 4,404 feet below and serve the $2 billion Tubular Bells project under development by Hess, the operator, and its partner, Chevron. Gulfstar I is scheduled to start up when Tubular Bells goes on production in mid 2014. Capacity will be 60,000 bbl. of oil and 200 MMcf of gas per day. Williams holds a 51% interest with joint-venture partner Marubeni holding the balance.

Offshore midstream operators typically do minimal processing at sea, Miller says.

“When you build a platform, whether it’s on the shelf or out in the deep water, on the platform you’re doing three-phase separation. It’s the blood, guts and feathers— that basically means oil, gas and water,” he says, adding NGL separation at sea “would not be an economic activity.”

Processing produced water can be complex before the water goes over the side, but is necessary to avoid the formation of methane hydrates in pipelines. Environmental rules mandate a strict no-sheen policy around platforms so all hydrocarbons must be taken out.

“The people out there know how to make sure that’s done properly, and then the oil will go into an oil pipeline off the platform and come to the beach and the gas and the NGLs in the gas will go into a separate gas line and that will come onto the beach. But that’s a rich gas stream, and, of course, on the floating production system, the gas stream would also be dehydrated,” Miller says.

The trend has been for the deepwater fields to have very rich associated gas, he points out.

“We’re seeing less gas, more oil and very high NGLs in the gas stream. Even though you might only have, say, 50 million a day of gas coming off a platform now—whereas 10 years ago it might have been 200 million a day—in terms of gas-liquids content, they rank exactly the same. The gas is so much richer,” Miller adds. Offshore has a similar standardization trend to onshore midstream projects. “We’ve got other projects that we’re looking at that hopefully will be following that one,” Miller says of the basic Gulfstar design. “I’m very optimistic, but that’s just kind of the natural evolution and development of the space, I think.”

Enterprise Products Partners is among the other big midstream names with a significant presence in the Gulf. It has interests in six processing platforms, including the big Independence Hub platform with a capacity of 800 MMcf per day. In total, Enterprise operations can process 1.8 billion cubic feet (Bcf) per day of gas and 89,000 bbl. of oil per day.

It also has 2,269 miles of pipelines under water, including 1,280 miles of gas pipelines with a combined capacity of 3.7 Bcf per day, and 989 miles of oil pipelines with a combined net capacity of 1.1 million bbl. per day.

The firm’s current capex plan includes the Lucius crude pipeline with a scheduled in-service date of third quarter of 2014. It will serve Anadarko Petroleum’s oil-rich Lucius field.

Enbridge at sea

One of the biggest midstream players in the Gulf is Enbridge, which says its pipelines move approximately 50% of the natural gas produced from deepwater fields. It has severalGulf-related projects under way, including a $200 million expansion of its Venice, Louisiana, gas condensate stabilization plant. The project will allow the facility to handle production from Shell’s new Olympus project in Mississippi Canyon offshore Louisiana. The expansion will more than double capacity to approximately 12,000 bbl. of gas condensate per day and is expected to be in service late this year.

The gigantic Olympus tension-leg platform moved out from Ingleside, Texas, in July and will be tethered in 3,000 feet of water. Shell expects to go into production next year, flowing at a rate of 100,000 bbl. of oil equivalent per day.

Enbridge also has agreements with Chevron and its partners to expand its existing central Gulf of Mexico pipeline system with the new Walker Ridge Gathering System. Walker Ridge will provide gas gathering services for the proposed Jack, St. Malo and Big Foot ultra-deepwater developments.

Walker Ridge will include 170 miles of 8-inch and 10- inch pipeline lying at depths of as much as 7,000 feet and have a capacity of 100 MMcf per day. The $400-million project is scheduled to enter service in late-2014.

Meanwhile, the company plans a crude pipeline to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corp., to existing lines in the area.

The Heidelberg Lateral Pipeline will be a 20-inch, 34-mile pipeline originating in Green Canyon Block 860, approximately 200 miles southwest of New Orleans in 5,300 feet of water. The $100-million project is scheduled to start flowing in 2016.

The future

Looking ahead, Miller sees continuing OCS midstream development as new plays emerge.

“The producers are getting in the new formations, Lower Tertiary. There are also some Jurassic-age plays over in the eastern part of the Gulf that are being developed, and all of these formations are, in general, a little more complex than the last things that were developed. We’re seeing a lot more water injection, even producers talking about injecting other materials into the formation to help drive the oil to the surface and maintain the reservoir pressures.

“We’re also seeing wells that are producing at much higher pressures and much higher temperatures,” Miller adds. “In some instances, that will require processing equipment that doesn’t even exist yet.”

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